Subsurface well bore shifting tool

ABSTRACT

A subsurface well bore tool for shifting a member, such as a sleeve structure for actuating safety valve, the tool includes a mandrel carrying normally retracted latch means expandable laterally by a fluid pressure operated actuator shiftable along the mandrel into latching engagement with the member or sleeve structure, enabling the actuator to then shift the member or safety valve sleeve structure longitudinally in one direction, the actuator being shiftable longitudinally in the opposite direction to permit retraction of the latch means and withdrawal of the shifting tool from the well bore.

[ 1 Oct. 14, 1975 United States Patent [191 Crowe 3,678,998 7/1972 Cockrell 166/123 3,746,093 7/1973 166/123 SUBSURFACE WELL BORE SHIFI'ING TOOL [75] Inventor: Talmadge L. Crowe, Houston, Tex w Primary Lxammer.1ames A. Leppmk Baker Oil Tools, Calif.

L05 Angeles, Attorney, Agent, or FirmBernard Kriegel [73] Assignee:

June 3, 1974 ABSTRACT [22] Filedz [21] Appl' 475587 A subsurface well bore tool for shifting a member,

such as a sleeve structure for actuating safe ty valve, the too1 includes a mandrel carrying normally re- 2 7 9 8 2 N mu aJ 0 m 35 C7 2 w M o w ma 1 e m m .w D .4 6 .1

abandoned, which is a division of Ser. No. 243,806, traded latch means expandable laterally y a fluid April 13, 1972, Pat. No. 3,771,603. pressure operated actuator shiftable alon g the mandrel mber or sleeve structure, enabling the actuator to then shift the member or safety valve sleeve structure longitudinal] one direction, the actuator being shiftable lon into latching'engagement with the me y in gitudi- [52] U.S. Cl.

[58] Field of Search........... 166/123, 124, 125, 181,

166/ 182, 212, 237, 189, 217 nally in the opposite direction to permit retraction of the latch means and withdrawal of the shiftin from the well bore.

g tool [56] References Cited UNITED STATES PATENTS 11 Claims, 30 Drawing Figures 3,670,821 6/1972 Tamplen............................ 166/125 Oct. 14,1975 Sheet10f13 3,912,008

US. Patent Sheet 2 of 13 Oct. 14, 1975 US. Patent U.S. Patant Oct. 14, 1975 Sheet 3 0f 13 3,912,008

US. Patent 0a. 14, 1975 Sheet4 of 13 3,912,008

US. Patent Oct. 14,1975 Sheet 6 of 13 3,912,008

US. Patent 0:.14,1975 Sheet80fl3 3,912,008

US. Patent 0a. 14, 1975 Sheet 9 of 13 3,912,008

No v

WNW

MSW

US. Patent Oct. 14,1975 Sheet 10 of 13 3,912,008

UHN

Sheet 12 of 13 Oct. 14, 1975 US. Patent SUBSURFACE WELL BORE SIIIFTING TOOL This application is a division of application .Ser. No. 275,910, filed July 28, 1972, now abandoned, which is a division of application Ser. No. 243,806, filed Apr. I3, 1972, now U.S. Pat. No. 3,771,603. a

In the production of well fluids, such as oil and/or gas, from wells, it has been the practice to provide automatically closable shutoff or safety valves which are located downhole in the well and are held open by control fluid pressure, the valves closing automatically when control fluid pressure is purposely reduced to allow the valves to close or damage occurs to the control fluid system at the well head or on an offshore platform.

Such valves are employed below the well head, and in the case of offshore wells the valves are installed below the mudline at such depthas may be desired or established by regulations, so that in the event of damage to the well caused by shifting earth or subsidence, the wells can be shut in to avoid loss of valuable well fluids into the water and, also, to avoid contamination of the water and the shore.

Many offshore wells are produced from spaced well zones through separate strings of production tubing, and a safety or shutoff valve is required for each zone. Since, from time to time, it is necessary to perform various remedial operations through the tubing strings, it is preferred that the safety valves have a full bore opening which will allow wireline tools to pass through the safety valves. On the other hand, it is also preferred that the safety valves be easily removed from the well for service or repair. While safety valves adapted to be run into the well and landed in a seat on a wireline and retrieved on wireline are relatively simple to run and retrieve without requiring that the tubing string be pulled from the well, such wireline valves, in general, do not have a full bore opening through which remedial operations can be performed through the production tubing, particularly if the well is cased with comparatively small casing so that the valves must be small in diameter.

Full opening valves have been made up in the tubing strings and run into the well in the tubing string. Accordingly, repair or service of such tubing string safety valves has required that theentire tubing string be hoisted, at lease until the valve is accessible. Such operations have generally involved killing the well, with prospective damage to the productive formation, as well as the use of heavy hoisting equipment capable of lifting an entire tubing string which may be many thousands of feet in length.

In addition, when an offshore well is cased with comparatively small diameter, casing, a limitation is inherently imposed on the size of the tubing valves that can be run into the well on tubing, as well as on wireline.

In the above-identified applications of which this application is a division, there is disclosed a plural zone, subsurfacesafety valve system which is conveniently usefulin the control of a multiple zon'e well. The subsurface valve assembly is run into the well on upper tubing strings and is landed in a receptacle provided in a tubing hanger which isanchored in the well casing, say, below the mudline of an offshore well, and supports the major production tubing weight suspended below thetubing hanger. The plural safety valve can readily be'retrieved from the tubing hanger without requiring that the entire production tubing string be pulled from the well, and without requiring that the well be killed. However, even though the pulling of the upper tubing strings and the subsurface valve assembly from the tubing hanger may be a comparatively simple task, there is a resultant loss of well production time from the several well zones.

The present invention provides a shifting tool for shifting a safety valve member, which has been closed by well fluid pressure, to an open position, in the event that a control fluid pressure responsive operating device should fail, which normally can hold the valve member open. Such shifting of the valve member to open position enables an auxiliary wireline retrievable safety shutoff valve to be installed, which is also operable by the same control fluid pressure that was holding the valve member open, whereby the safety function of the subsurface valve means is maintained until the entire subsurface tubing valve is pulled. The shifting tool is adapted to be removably seated in the tubing valve and operated by fluid pressure supplied to the tubing string to actuate a sealing sleeve which bears against the safety valve member, to move the safety valve member to its opened position, at which position it is retained.

This invention possesses many other advantages, and has other purposes which may be made more clearly apparent from a consideration of a form in which it may be embodied. This form is shown in the drawings accompanying and forming part of the present specification. It will now be described in detail, for the purpose of illustrating the general principles of the invention; but it is to be understood that such detailed description is not to be taken in a limiting sense.

REFERRING TO THE DRAWINGS FIG. 1 is a digrammatic illustration showing dual safety valve apparatus installed in a tubing hanger anchored in a well casing extending through vertically spaced productive well zones which are isolated from one another by packers, and from which well fluid are produced through a pair of production tubing strings;

FIGS. 2a, 2b, 2c and 2d together constitute a view generally in elevation, but with certain parts broken away, showing the subsurface valve assembly landed in the tubing hanger, FIGS. 2b through 2d, respectively, constituting successive downward continuations of FIG. 2a;

FIG. 3 is a view, partly in elevation and partly in section, as taken on the line 3-3 of FIG. 2d;

FIG. 4 is a horizontal section as taken on the line 4-4 of FIG. 2b;

FIG. 5 is a horizontal section as taken on the line 5-5 of FIG. 2d;

FIG. 6 is a horizontal section as taken on the line 6-6 of FIG. 2d;

FIG. 7 is a horizontal section as taken on the line 7-7 of FIG. 20;

FIG. 8 is a horizontal section as taken on the line 8-8 of FIG. 2b;

FIGS. 9a and 9b together constitute a vertical section through one of the subsurface valve assemblies, as taken on the line 99 of FIG. 7, FIG. 9b constituting a downward continuation of FIG. 9a, and the valve being shown in the normally closed condition;

FIGS. 10a and 10b together constitute a view generally corresponding to FIGS. 9a and 9b, but showing the valve assembly in the open condition;

FIG. 11 is a horizontal section as taken on the line llll of FIG. 9a;

FIG. 12 is a horizontal section as taken on the line l2l2 of FIG. 9a;

FIG. 13 is a fragmentary horizontal section as taken on the line l3-l3 of FIG. 9b;

FIG. 14 is a fragmentary vertical section as taken on the line l4l4 of FIG. 7;

FIG. 15 is an exploded detail view in perspective, showing a typical ball valve and a removable side closure and valve supporting member;

FIG. 16 is a fragmentary detailed view, partly in elevation and partly in section, showing the ball valve in a closed position;

FIG. 17 is a view generally corresponding to FIG. 16, but showing the ball valve shifted longitudinally downwardly from engagement with the resilient seal but prior to rotation towards the open position;

FIG. 18 is a view corresponding to FIGS. 16 and 17, showing the ball valve rotated towards an open position;

FIG. 19 is a view corresponding to FIGS. 16 through 18, but showing the ball valve in the full open position;

FIGS. 20a and 20b together constitute a vertical section, with certain parts shown in elevation, showing a shifting tool disposed in a valve assembly with the valve in the closed position prior to movement of the valve to the open position by the shifting tool, FIG. 20b constituting a downward continuation of FIG. 20a;

FIGS. 21a and 21b together constitute a view generally corresponding to FIGS. 20a and 20b, but showing the valve shifted to the open position by the shifting tool, and the valve being locked open; and

FIGS. 22a and 22b together constitute a vertical section with certain parts shown in elevation, and showing a wireline retrievable shutoff valve seated and locked in the bore of the locked open main shutoff valve.

As seen in the drawings, the invention is shown in a plural safety valve for an offshore well. Referring first toFlG. l, a well bore W extends downwardly into the earth below the ocean floor F through vertically spaced well fluid producing zones Z1 and Z2. A casing C is set in the well bore and perforations P in the casing establish communication between the productive zones 21 and Z2 and the casing C. Set in the casing C is an upper packer Pl located above the productive zone Z1 and a lower packer P2 located in the casing between the productive zones 21 and 22. A first production tubing string Tl extends through the packer P1 and open into the casing therebelow to communicate with the productive zone Z1, and a second production tubing string T2 extends downwardly through the upper packer P1 and downwardly through the lower packer P2 into the casing therebelow for communication with the productive zone 22. The tubing strings T1 and T2 may extend a number of thousands of feet downwardly in the casing to the packers P1 and P2 and the tubing strings T1 and T2 are supported by tubing hanger means TH which is set or anchored in the well casing and forms a seat for a shutoff valve assembly V which comprises dual shutoff valves V1 and V2 for the respective tubing strings TI and T2. The tubing hanger TH and the valve assembly V are located below the ocean floor or the mudline of a body of watenat a desired or required depth of say 500 to 1000 feet, more or less. The casing C extends upwardly through the water to a production platform or barge PP, as shown in the diagrammatic illustration.

However, as is well known, the well may be completed at the ocean floor and one or a number of additional casings (not shown) may be set in larger diameter well bores, and the casing C may be suspended or hung from a casing hanger located at the ocean floor, in which case, a conductor pipe or other casing (not shown) may extend to the production platform PP. In any event, upper production fluid tubings T3 and T4 extend upwardly from the respective valves V1 and V2 of the valve assembly V and are connected with the usual Christmas Trees CT on the platform PP whereby the flow of well fluids from the well zones 21 and Z2 may be controlled or manually shut off. Flow lines FL are provided to conduct well fluids from the Christmas Trees to suitable reservoirs or tanks (not shown).

As will be later described, the respective subsurface valves V1 and V2, which are normally closed, are adapted to be held open, to enable the flow of production fluids therethrough, by means of control fluid pressure supplied through a control fluid conduit CF, or through a pair of such conduits, from a source of control fluid pressure CP. So long as the control fluid pressure is adequate to maintain the subsurface valves V1 and V2 open, well fluids may flow from the zones Z1 and Z2 to the respective flow lines FL, but, if it is desired for any reason to close either of the shutoff valves Vl or V2, or in the event of damage of the control fluid tubing, the control fluid pressure may be reduced so that the subsurface valves V1 and V2 are automatically closed, thereby shutting the well in at a location below the ocean floor, to prevent continued production fluid flow.

The tubing hanger assembly TH and the tubing strings T1 and T2 are adapted to be lowered from the platform PP downwardly through the casing C on a settingtool, as more particularly described in the application of which this is a division, and the valve assembly V is thereafter adapted to be lowered through the easing C into the tubing hanger TH on the upper tubing stringsT3 and T4. Likewise, the valve assembly V can be retrieved from the tubing hanger TH, so that under normal circumstances requiring repair or service of the subsurface valve assembly V, it is not necessary to pull the entire dual tubing strings T1 and T2, as has heretofore been the practice. Since only the comparatively short upper tubing strings T3 and T4 need be pulled from the well to remove the valve assembly V, and the substantially longer tubing strings T1 and T2 remain in the well, the platform PP need not be equipped with or supplied with high-powered hoisting apparatus. Instead, the platform PP may simply be provided with a small low-powered hoist mechanism or a gin pole hoist. In addition, the tubing strings T1 and T2 can be plugged off at or below the tubing hanger TH to enable the service or repair of the valves V1 and V2 without requiring that the well be killed.

As seen in FIGS. 1, 2d and s, the tubing hanger .TH.

comprises a body section 10 having an upwardly extended tubular guide section 11, the upper end edge 12 of which is arched downwardly from a peak 13, in opposite directions, to a vertically extended slot 14 at the side of the guide section 11 diametrically opposite the peak 13. Internally of the guide section 11, between the lower end of the slot 14 and the body section 10, is a thread 15 to which a setting tool is connectable, as disclosed and claimed in the companion application Ser.

' No. 275,911, filed July'28, [972, for Tubing Hanger Apparatus", now U.S. Pat. No. 3,830,295. Below the internal thread is an internal flange 16 which provides a downwardly facing shoulder 17, for anchoring the valve means V in the hanger TH, as will be later described.

Extending downwardly into the body section 10 from the guide section 11 are a pair of diametrically spaced fluid passages 18, 18, at the upper end of each of which is a cylindrical receptacle or socket 19. At the lower end of the body section 10, the tubing strings T1 and T2 are connected thereto in communication with the respective passages 18, 18.

Anchor means 34 for the tubing hanger may be as described and shown in the aforementioned application of which this is a division, and comprise suitable slip elements 46 and 47 which are expansible into anchoring engagement with the casing C.

When the setting tool has been removed from the well casing, the tubing hanger assembly is then in condition to receive the dual valve assembly V, as seen in FIGS. 2a through 2d.

The dual valve assembly V, as previously indicated, comprises, in the illustrated embodiment, a pair of valves V1 and V2, since the apparatus is shown as applied to producing from a pair of well zones Z1 and Z2, but it will be understood that the invention is applicable, also, to valve assemblies used in the production of more or less than two well zones.

At its lower end, as seen in FIGS. 2d and 3, the valve assembly V is adapted to be received in the upper tubing hanger body section 11 and to be latched in place by releasable latch means 125 beneath the internal flange 16 in the hanger body section. At diametrically spaced locations in a cross-head 126 of the latch means 125, the latch means 125 has elongated laterally opening spaces 127, 127 accommodating flow tubes 128 and 129 which are respectively adapted to establish communication between the tubing strings T1 and T2 and the valve assemblies V1 and V2, respectively.

At their lower ends, the flow tubes 128 and 129 have sealing end portions 130 and 131, respectively, each having sealing ring means 132 engageable within the bores or receptacles 19 in the tubing hanger body 10. The flow tube 128 extends upwardly from the crosshead 126 and is connected at 133 to a length of tubing 134 which extends further upwardly a suitable distance, and is connected at 135 to the housing 136 of the upper valve assembly V1, which will be hereinafter described. The flow tube 129 also extends upwardly from the cross-head 126 and is connected at 137 to the valve assembly V2, which is spaced vertically downwardly from the valve assembly V1 to enable utilization of valve assemblies V1 and V2 having full bore flow passages, as will also be later described. Extending upwardly from the valve housing 138 through swivel means 139 is a rotatable tubular member 140 which is connected at its upper end by a coupling 141 to the tubing string T4 above the connection of the tubing string T3 to the valve assembly V1, as seen in FIG. 2a. Rotation of the tubing string T4 and, thus, the tubular member 140 is utilized to engage and release the latch means 126 when the valve assembly V is run into the tubing hanger TH.

The flow tubes are retained in parallel, assembled relation by a vertically split body 142 comprising opposed half sections 143 and 144, as seen in FIG. 6, clamped together by fasteners 145. The bodysections 143, 144 have internal grooves 146 which receive annular ribs 147 on the flow tubes 128, 129 to hold the latter against relative axial movement.

When the valve assembly V is being lowered into the tubing hanger TH, a key 148 on one side of the assembly, shown on the flow tube 129, and engageable with the peak 13 of the hanger body section 11 will cause rotation of the valve assembly V, as the key 148 rides downwardly on the inclined surface 12 and is guided into the vertical slot 14, whereby the lower ends 130, 131 of the flow-tubes 128, 129 will be properly positioned or oriented so as to be stabbed into the bores or receptacles 19 in the hanger body 11.

The latch means 125 referred to above, comprises a plurality of resilient, normally retracted collett fingers 150 depending from the cross-head 126 and having outwardly projecting latch lugs 151 at their lower ends. The lower ends of the latch fingers are expansible outwardly by a wedge surface 152 on the split body 142 when the cross-head 126 is moved downwardly relative to the body 142, from the position of FIG. 2d to the position of FIG. 3. Means 155 are provided for normally holding the latch fingers 150 in the retracted positions,

and spring means 156 are provided for actuating the cross-head 126 downwardly to cam the fingers 150 outwardly.

More particularly, a pair of bolts 157 extend through the cross-head 126 and have their heads 158 engageable beneath the cross-head 126 to hold the latter in an upper position, as seen in FIG. 2d. These bolts 157 are threaded into a plate 159 which is connected to a pull rod 160, the pull rod extending upwardly alongside the length of tubing 134 and being connected, as seen in FIG. 2b, to a non-rotatable nut 161, having a notch 162 for straddling the tubing 134 to prevent rotation of the nut. The nut 161 has a threaded bore 163, in which a complemental thread 164 on the rotatable tubing section 140 is engaged. Accordingly, when the tubing string T4, which, as previously indicated, is connected to the tubing section 140, is rotated, the nut 161 is moved axially on the tubing section 140, downwardly, from the position of FIG. 2b, to allow downward movement of the plate 159 and the bolts 157.

The spring means 156 are operable to force the cross-head 126 downwardly and comprises a pair of coiled compression springs 165 disposed about the bolts 157 and seating at their lower ends in bores 166 in the cross-head 126 and at their upper ends against a spring seating plate 167 which abuts beneath the lower valve housing 138. When the cross-head 126 is moved downwardly by the springs 166, the lugs 151 on the latch fingers 150 are cammed by the cam surface 152, outwardly for engagement beneath the latch shoulder 17 of the tubing hanger body section 11.

As seen in FIGS. 2a through 2c, the control fluid conduit CF is connected by a fitting 170 to the upper valve housing 136 of the valve V1 and passage means 171 in the housing 136 conduct control fluid to an outlet fitting 172 which is connected to a conduit 173 leading to an inlet fitting 174 for the lower valve V2. However, if preferred, plural control fluid tubings CF may be employed to supply control fluid pressure to the valves V1 and V2.

The fluid pressure responsive shutoff valve V1 is made according to the invention and is representative of the two valves V1 and V2 and will now be described.

In this form, as seen in FIGS. 9a, 9b and 10a, 10b, the valve assembly comprises the outer body 136 and an upper tubular sub 136a which is connected with the lower end of the tubing string T3. The upper body 136a is threadedly connected at 175, at its lower end to the body 136, which, in turn, as previously described, is threadedly connected at 135 to the flow tube 134, which seats in one of the bores or receptacles 19 in the tubing hanger body 10.

A ball valve 176 is disposed within the body 136 and has a passage 177 for the flow of well fluid when the ball valve is in the open position, with the passage 177 aligned with the body 136, the ball valve being rotatable 90", as will be later described, to a closed position, in which flow of well fluid through the body 136 is prevented.

Normally, the ball valve 176 is biased to a closed position by a lower sealing and actuating sleeve 178, which is reciprocable in the valve body 136 between an upper position, as seen in FIG. 9b, and a lower position, as seen in FIG. 10b. The sleeve 178 is piloted in a reduced bore 179 in the body 136, and the lower end of the sleeve extends into a bore 180 in the upper end of the tube 134. A coiled compression spring 181 is disposed between the upper end of the tube 134 and a seating shoulder or ring 182 on the sleeve 178, and biases the sleeve 178 and the ball valve 176 upwardly. Externally, the ball valve 176 has a spherical sealing surface 183 sealingly engageable by a companion sealing end surface 184 at the upper end of the sleeve 178.

Above the ball valve 176 is an upper valve actuating and sealing sleeve 185 having a lower end sealing surface 186, which is complemental to the spherical valve surface 183 of the ball valve 176. At its upper end, the sleeve 185 has an enlarged piston section 187 which is slidably disposed within a cylinder portion 188 of the valve body 136. Below the piston section 187 is a cylindrical section 189 smaller than the outside diameter of the piston section 187. Between the cylindrical section 189 and the cylindrical wall 188 is a sleeve 190 engaged by an external seal ring 191 on the cylindrical section 189 and having an external seal 192 engaging with the cylinder wall 188. At its lower end, the sleeve 190 abuts with an upwardly facing shoulder 193. The difference between the annular cross-sectional area of the sleeve 190 and the annular cross-sectional area of the upper end 194 of the piston section 187 constitutes the net piston area of the piston section 187 exposed, as will be later described, to control fluid pressure to hold the ball valve 176 open. The piston section 187 extends into an annular space 195 defined between the cylindrical wall 188 and a sleeve 196 which is releasably connected by suitable means such as shearscrews 197 to a skirt 198 on the lower end of the upper body section 136a, the sleeve 196 carrying a seal ring 199 engageable within the skirt 198, and the skirt 198 having a seal ring 200 engageable in the cylindrical wall 188. This sleeve 196 will be more particularly described hereinafter.

The control fluid passage 171, previously referred to, communicates through a port 201 with the annular space 195 which constitutes a control fluid pressure chamber in which control fluid pressure is operable on the net piston area of the piston section 187 of the sleeve 185 to provide a downward force adapted to overcome the upward force applied to the ball valve 176 by the lower valve actuating sleeve 178, when the ball valve 176 is to be opened by moving the ball valve from the position of FIG. 9b to the position of FIG. 10b, as the upper valve actuating and sealing sleeve 185 is forced downwardly. When the over-riding control fluid pressure is relieved, the pressure of production fluid acts, to close the ball valve 176, across the combined areas of the upper sleeve or piston section 187 and the secondary sleeve 190 when the latter shoulders at 190a, as seen in FIG. 10a.

Preferably, the valve assembly includes resilient sealing means 202 engageablewith the ball valve 176 when it is in the closed position. In the embodiment now being described, the resilient sealing means 202 comprises a seal carrier ring 203 having an annular elastomeric seal ring 204 engageable with the ball valve 176 externally of the seating surface 186 at the lower end of the sleeve 185. The seal carrier ring 203 is normally biased downwardly by a coiled compression spring 205 which seats against a seating ring 206 carried within the valve body 136.

The respective valve assemblies V1 and V2 and full opening valve assemblies through which remedial operations can be performed when the ball valve is opened. The valve assembly, as shown, is more particularly the subject matter of the companion application Ser. No. 286,151, filed Sept. 5, 1972, now US. Pat. No. 3,797,573.

In order to provide a ball valve 176 of maximum diameter, the ball valve 176 is installed in the body 136 through a side opening 207 which is closed by a valve supporting closure member 208 which fits within the opening 207, and is sealed therein by a suitable seal ring 209. Referring again to FIG. 2b, it will be noted that the closure and valve support member 208 is adapted to be secured to the valve body 136 by a suitable number of fasteners 210, and as best seen in FIG. 8, the closure member 208 includes a guide section 21 1 having a bore 212 through which the tubular member rotatably extends.

In order to support the ball valve 176 and cause rotation thereof in response to movement of the ball longitudinally between the sleeves and 178, the valve supporting member 208 has a pin or lug 213 projecting therefrom in alligned opposition to a corresponding pin or lug 214 carried within the valve body 136, and the ball valve 176 has at its opposite sides corresponding slots 215 in which the respective pins or lugs 213 and 214 are engageable for rotating the ball valve 176 between the opened and closed positions, as best illustrated in FIGS. 16 through 19. In these views, the side of the ball valve 176 supported by the closure 208 is illustrated, but similar structure will be understood to be located at the other side of the ball valve, also. In FIG. 16, the valve is shown fully closed and sealed by the sleeves 178 and 185 as well as by the resilient sealing means 202. In FIG. 17, the valve 176 has been shifted downwardly away from the resilient seal means 202 through an initial increment of non-rotative longitudinal movement. In FIG. 18, the ball valve 176 is in the partially opened position. In FIG. 19, the ball valve 176 is in the fully opened position.

More particularly, the ball valve member 176 on each of its opposite sides has a chordal flat surface 216 adjacent to the diametrically opposite portions of the body 136 and the support 208. The slot 215 extends radially with respect to the axis of. rotation to the ball valve member 176, andat right-angularly spaced locations, the ball face 190 is recessed to form a stop surface 217 and a stop surface 218 cooperable with fixed stop lug surfaces 217a and 218a on the closure 208 to limit rotation of the ball 176 between the extremes of FIG. 16 and FIG. 19. When the ball valve member 176 is in the position of FIG. 16, the stop surface 217 engages thevertical stop surface 217a, thereby limiting rotation ofthe valve member 176 to the position at which the valve is open. The stop surface 218 engages the stop surface 2180, as shown in FIG. 19 to limit rotation of the valve member 176 to the position at which the valve is closed. Such rotation between the open and closed positions is caused by longitudinal or vertical movement of the valve member 176 relative to the body 136. As previously indicated, the ball member 176 is actuated or shifted longitudinally by longitudinal movement of the upper actuator sleeve 185 and the lower actuator sleeve 178, as indicated by the arrows in FIGS. 17 and 19. The slot 215 is formed in such a manner as to cause such rotation of the valve member 176 as the latter moves vertically or longitudinally within the body 136. Thus, as seen in FIG. 16, the slot 215 is formed in the valve member 176 by opposed walls which are disposed at a right angle to one another and designated 215a and 2l5b and which respectively are parallel to the stop surfaces 217a and 217b. At the apex of the angle defined between the walls 215a and 215b, the slot opens radially inwardly at 2150. Thus, the relationship between the pin 213 and the wall 215!) is such that the ball valve 176 will be rotated from the position of FIG. 16 to the position of FIG. 19 when the valve member 176 moves downwardly relative to the pin 213, and, conversely, the flat wall 215a will engage the pin 213 and rotate the ball valve member from the position of FIG. 19 to the position of .FIG. 16 upon upward movement of the valve member 176. However, it will be noted that when the valve member 176 is in the position of FIG. 19, the pin 213 clears the flat wall 215a so as to allow freedom of longitudinal movement of the ball valve 176 after the stop surface 218 engages the stop 218a, and correspondingly limited free downward movement of the ball valve 176 is permitted when the ball valve is open, as seen in FIG. 16, where the pin 213 clears the slot wall 215a, and the stop surface 217 engages the stop 217a. Such free or lost motion connection of the ball valve 176 and the rotating pin 213 relieves the connection of damaging forces when the ball valve is in either of its closed or opened positions, and in addition saves the resilient seal 202 from relative rotative movement of the ball valve 176.

When the ball valve 176 is closed and is to be opened by applying control fluid pressure to the piston chamher 195, there may be substantial differential pressure across the valvet'en'ding to hold it closed, and in order to equalizethe pressure across the valve, equalizing valve means220 are provided, as best seen in FIG. 14, for establishing communication between a port 221 below the ball valve 176 (FIG. 9b)'and a port 228 above the valve 176 (FIG. 9a), via the'elongated passage 223 in the'valve body 136. The port 221 communicates with the annular space 224 between the body 136 and the lower valve actuating sleeve 178 which communicates with the'passage through the tubular member 134 through radial ports 22 in the upper end of the member 134, when the valve 176 isclosed, as seen in FIG. 91 Above the ball valve 176, the skirt 198 of the upper valve body section 136a has a number of radial ports 226 communicating between the flow passage through the valve assembly and an annulus 227 which in turn communicates through a port 228 with a chamber 229 of the equalizing valve means 220. The equalizing valve chamber 229 is provided by a tubular insert 230 retained in a bore 231 in the body 136 by a sealing plug 232. Seals 234 and 234a on the insert 230 engage in the bore 231 and a reduced bore 235. A valve member 236 is reciprocable in the insert 230 and has its lower end 237 provided with a seal 238 slidably engaging within the insert 230 below inlet ports 239 in the insert which establish communication between the port 228 and the valve chamber 229, so that above the seal 238, the chamber 229 is exposed to the flow passage through the upper valve body 136a. At the upper end of the equalizing valve member 236 is a head 240 engageable with a seat 241 under the influence of pressure below the ball valve 176 supplied to an inlet chamber 242, above the head 240, via the passage 223 and via a radial port 243 in the body 136 and ports 244 in the insert 230. A rod 245 slidably extends downwardly through the lower end of the insert 230 and into the bore 235, and a coiled spring 246 engaged the insert 203 and an adjustable spring seat 247 on the rod to provide a downward bias closing the head 240 against the seat 241. Leading into the bore 235 of the equalizing valve 220 is a port 248 which communicates with the control fluid chamber of the shutoff valve means.

It will now be apparent that so long as the pressure differential across the closed ball valve 176 is such that well pressure in the equalizing valve chamber 242 and the spring 246 cause a net downward force holding the valve head 240 seated, in excess of the force upwardly caused by control fluid pressure in the bore 235, there will be no communication between the ports 221 and 228, respectively, below and above the ball valve 176. However, as control fluid pressure is increased to open the shutoff valve 176, the increased pressure acts upwardly on the effective piston area at the lower end of the equalizing valve member 236 and will open the equalizing valve head 240, whereby pressure will equalize between the lower ports 221, through passage 223, ports 243 and 244, valve chambers 242 and 229, ports 239, and the upper equalizing port 228.

The effective areas in the equalizing valve means 220 and the force of the spring 246 are selected, as com pared with the effective area of the shutoff valve actuating piston section 187 of the sleeve 185, so-that the equalizing valve means 220 will open first, and thereby relieve the main shutoff valve 176 from the effect of differential pressure thereacross.

In order to assure that no back flow can occur when the shutoff valve 176 is open and the well is flowing therethrough, a back flow preventing valve 223a is provided between the equalizing valve chamber 242 and the passage 223 In order to enable control fluid pressure to be supplied to both of the valve assemblies V1 and V2 in the valve means V, as previously indicated, the control fluid pressure chamber or bore 235 of the equalizing valve means 220 of the upper valve V1 has a passage 235a leading to the fitting 172, which in turn communicates with the lower valve assembly V2.

In the use of shutoff valves, such as the valve assembly V1 or V2, to control flow from a plurality of well zones, it may occur, under various circumstances, such as seal failure, that one or more of the shutoff valves will not-open under applied control fluid pressure. In such event, it may be necessary to pull the shutoff valve means from the well in order to repair and replace the shutoff valve means. In accordance with the present invention, however, means are provided whereby the valve V1 or the valve V2 may be opened mechanically and locked open to allow continued production from one or both of the well zones Z1 and Z2. In addition, the present invention enables the use of an auxiliary or secondary shutoff valve, adapted to be run into and anchored in the locked open valve assembly V1 or V2.

As seen in FIGS. 90, 9b, and in FIGS. 10a, 10b, the sleeve 196 is held by the shear screws 197 in an initial upper position, as previously described, and the sleeve 196 cooperates with the body 136 to form the control fluid pressure chamber or annular space 195. Initially released lock means 250 are provided, whereby, when the sleeve 196 is shifted downwardly, it will be locked in the lower position. When the sleeve 196 is shifted downwardly, it engages a shoulder 251 on the sleeve 1 85 and shifts the latter downwardly to open the ball valve 176. The sleeve shifting tool SS of FIGS. a, 20b, and FIGS. 21a, 21b provides means for shifting the sleeve 196 downwardly.

More particularly, the lock means 250 includes a resiliently contractable, split lock ring 252 having external upwardly facing buttress teeth 253. Beneath the lock ring 252 is an expander 254 which is secured to the sleeve 196 by fasteners 255 and has an expander surface 256 engageable within the lock ring 250 to exp'and the latter when it is lockingly engaged with internal teeth 257 within the body 136. i The sleeve shifting tool SS, as seen in FIGS. 20a and 20b, comprisesan inner mandrel 260 connected by a rope socket 261 to a wireline 262, and having an inner rod 264 connected thereto at 265 and extending downwardly therefrom. The inner rod 264 has an elongated slot 266 through which a pin 267 extends. This pin 267 is carried by an actuator sleeve 268 which is slidably disposed upon an elongated support sleeve 269 of the mandrel, also having an elongated slot 270 through which the pin 267 extends. The support sleeve 269 is threadedly connected at 271 to a tubular body 272 of the mandrel about which is a suitable packing means 273 sealingly engageable within the upper body section 136a of the shutoff valve body 136. Above the packing 273 is a nut 274 having a downwardly facing shoulder 2 75 adapted to abut with the upwardly facing shoulder 276 in the body section 136a. The mandrel 260 is slidably disposed within an upward extension 277 of the nut 274 communicating via ports 278 in the nut 274 and. ports 279 in the lower end of the mandrel 260 with an inner annular space 280, so that fluid pressure in the tubing string T3 is applicable to the piston section 281 of the actuator sleeve 268, the piston section 281 having a seal ring 282 slidable within the valve body section 136a.

At its lower end, the actuator sleeve 268 slidably engages the support sleeve 269 below the slot 270 and has a seal ring 283 sealingly engaged with the support sleeve 269. At its lower end, the middle rod 264 has an enlarged end 284 initially sealingly engaged within a cylindrical wall 285 of the support sleeve 269, above a longitudinally ported spring seat 286. A coiled compression spring 287 engages the spring seat 286 and acts upwardly on a latch sleeve 288 having a plurality of normally retracted resiliently outwardly expansible fingers 289 on which are upper end lugs290. Upward movement ofthe latch sleeve 288 is limited by a collar 291 on thesupport sleeve 269 and engaged by. a solid ring section 292 on the latch sleeve 288. The lugs 290 on the fingers 289, when the shoulders 275 and 276, limit downward movement of the sleeveshifting tool SS in the valve body section 136a, are located above the upper end 293 of the sleeve 196 which, as previously indicated, is initially held in its upper position by the shear screws 197, so thatthe seal ring 199 on the sleeve 196 is initially disposed above a number of radial ports 294 in the skirt portion 198 of the upper. body section 136a of the valve assembly V1 or V2.

In order to shift the sleeve 196 downwardly, the actuator sleeve 268, to which fluid pressure is applicableto move the latter downwardly, initiallyengages the upper ends of the fingers 289 with a lower cam surface 2.95 v of the actuator sleeve 268 and flexes the fingers outwardly so that the lugs 290 thereon are engageable with the upper end 293 of the valve sleeve 196. Above the cam surface 295 on the actuator sleeve 268 is a down wardly facing shoulder 295, which, upon further downward movement of the actuator sleeve 268, engages the upper ends of the fingers 289 to transmitthereto a downward force, whereby, as seen in FIGS. 21a and 21b, the sleeve 196 shears the shear screws. 197 and moves downwardly. Since the sleeve 196 engages the shoulder 251, as previously described, on the upper valve actuator sleeve 185, the latter is also moved downwardly, thereby opening the ball valve 176, as also previously described. t

Such downward movement of thesleeve 196 causes the latch means 250 to be engaged, that is, the lockring 252 engages the internal teeth 257 within the valve body 136, thereby holding thevalve actuating sleeve in its lower position.

Thereafter, the sleeve shifting tool SS may be removed from the valve body section 136a by simply lifting the mandrel 260 with the wireline 262, thereby lifting the middle rod 264 until the bottom 2660 of the slot 266 contacts the pin 267, thereby lifting the actuator sleeve 268 until it again engages the tubular body 272, at which time, the resilient fingers 289 will again flex inwardly, retracting the lugs 290 to their original positions. r ,1

When the sleeve 196 is locked by the locking means 250 in the lower position, holding the shutoff valve 176' open, the sleeve 196 and the valve body section. 1360 are adapted to receive a conventional wireline retriev-' packing means 303 sealingly engaged within the sleeve.

196, and straddling the ports 226 and the ports 294 in the skirt 198 of .the upper body section 136a which are both in communication with an annular space 304 defined between the skirt 198 and the valvebody 300,

this annular space 304 being in communication, via the ports 294, with the annular space or control pressure chamber of the valve assembly V1 orV2.-Thus,

control fluid pressure supplied to the annular space 195,

via the inlet port 201 is admitted through a-valve port 

1. A shifting tool for moving an element longitudinally with respect to the tubular body of a well tool connected in a well pipe and having a bore in which said element is disposed, said shifting tool comprising: a mandrel adapted to be lowered through said pipe into said body, normally retracted latch means carried by said mandrel and expansible into engagement with said element, actuator means movable downwardly along said mandrel and said latch means to engage and expand said latch means outwardly to a position of engagement with the element, enabling joint downward movement of said actuator means and latch means to shift said element downwardly with respect to said body, and means carried by said mandrel and engageable with said actuator means to move said actuator means upwardly of said latch means to a position enabling said latch means to retract from said expanded position.
 2. In a shifting tool for moving an element longitudinally with respect to the tubular body of a well tool connected in a well pipe and having a bore in which said element is disposed, said shifting tool comprising: a mandrel adapted to be lowered through said pipe into said body, normally retracted latch means carried by said mandrel and expansible into engagement with said element, actuator means for shifting said latch means longitudinally in one direction with respect to said mandrel to move said element longitudinally with respect to said body, and means carried by said mandrel for moving said actuator means in the other direction following movement of said element, said mandrel having seal means sealingly engageable in said body, and said actuator means comprising a piston shiftable on said mandrel, said mandrel having fluid passage means for exposing said piston to the pressure of fluid in said well pipe above said seal means.
 3. In a shifting tool as defined in claim 2, said piston having means for initially expanding said latch means into engagement with said element and means for then shifting said latch means and said element.
 4. In a shifting tool as defined in claim 2, said piston having means for initially expanding said latch means into engagement with said element and means for then shifting said latch means and said element, said mandrel and said piston having means for effecting opposite movement of said piston and release of said latch means upon movement of said mandrel with respect to said element.
 5. In a shifting tool as defined in claim 2, said piston having means for initially expanding said latch means into engagement with said element and means for then shifting said latch means and said element, said mandrel having means for venting said fluid passage means upon movement of said mandrel with respect to said element, and said mandrel and said piston having means for effecting opposite movement of said piston and release of said latch means upon movement of said mandrel with respect to said element.
 6. In a shifting tool as defined in claim 2, said mandrel and said piston having pin and slot means enabling movement of said piston in a direction to actuate said latch means and shift said element and for shifting said piston in the opposite direction upon movement of said mandrel to release said latch means.
 7. In a shifting tool as defined in claim 2, said mandrel and said piston having pin and slot means enabling movement of said piston in a direction to actuate said latch means and shift said element and for shifting said piston in the opposite direction upon movement of said mandrel to release said latch means, and including spring means acting on said latch in said opposite direction.
 8. In a shifting tool for moving an element longitudinally with respect to the tubular body of a well tool connected in a well pipe and having a bore in which said element is disposed, said shifting tool comprising: a mandrel adapted to be lowered through said pipe into said body, normally retracted latch means carried by said mandrel and expansible into engagement with said element, actuator means for shifting said latch means longitudinally in one direction with respect to said mandrel to move said element longitudinally with respect to said body, and means carried by said mandrel for moving said actuator means in the other direction following movement of said element, said mandrel having seal means sealingly engageable in said body, said mandrel extending reciprocably through said seal means, said seal means and said mandrel having passage means extending through said seal means, said actuator means including a piston exposed to fluid pressure applied through said passage means, said mandrel having a tubular member on which said piston is shiftable and a rod extending into said tubular member, said rod and said tubular member having elongated slots and said piston having a pin extending through said slots whereby said piston is shiftable along said tubular member in one direction and said piston is shiftable in the other direction upon longitudinal movement of said rod in said tubular member.
 9. In a shifting tool as defined in claim 8, said piston and said tubular member having sealing means closing said slots.
 10. In a shifting tool as defined in claim 8, said piston and said tubular member having sealing means closing said slots, and normally closed valve means operable upon said longitudinal movement of said rod to open said tubular member.
 11. In a shifting tool as defined in claim 8, said piston and said tubular member having sealing means closing said slots, and said rod and said tubular member having normally closed valve means operable upon said longitudinal movement of said rod to open said tubular member. 